1. General Technical Field
The present disclosure relates generally to methods and systems for performing borehole seismic surveys relating to subterranean formations. More specifically, some aspects disclosed herein are directed to methods and systems for acquiring and processing waveform measurements in a borehole for characterizing subterranean formations having oil and/or gas deposits therein. The borehole measurements include accelerometer data that are acquired during deployment of a receiver array to derive, for example, tool orientation and position and well profile information.
2. Description of the Related Art
The following descriptions and examples are not admitted to be prior art by virtue of their inclusion in this section.
Logging and monitoring boreholes has been done for many years to enhance and observe recovery of oil and gas deposits. In the logging of boreholes, one method of making measurements underground includes attaching one or more tools to a wireline connected to a surface system. The tools are then lowered into a borehole by the wireline and drawn back to the surface (“logged”) through the borehole while taking measurements. The wireline is usually an electrical conducting cable with data transmission capability.
Seismic exploration can provide valuable information useful in, for example, the drilling and operation of oil and gas wells. Seismic measurements of the type described herein may also be used for a wide variety of purposes that are known in the fields of passive and active seismic monitoring. In seismic exploration, energy is introduced by a seismic source, for example, an active or a passive source of seismic energy, to create a seismic signal that propagates through the subterranean formation. This seismic signal is modified to differing degrees by features that are of interest. A receiver acquires the seismic signals to help generate a seismic map of the underground features. As a practical matter, the system may comprise a plurality of sources and receivers to provide a comprehensive map of subterranean features. Different configurations may yield two dimensional or three dimensional results depending on their mode of operation.
A vertical seismic profile (VSP) is a class of borehole seismic measurements used for correlation between surface seismic receivers and wireline logging data. VSPs can be used to tie surface seismic data to well data, providing a useful tie to measured depths. Typically VSPs yield higher resolution data than surface seismic profiles provide. VSPs enable converting seismic data to zero-phase data as well as enable distinguishing primary reflections from multiples. In addition, a VSP is often used for analysis of portions of a formation ahead of the drill bit.
Narrowly defined, VSP refers to measurements made in a vertical wellbore using acoustic receivers inside the wellbore and a seismic source at the surface near the well. In a more general context as used herein, however, VSPs vary in well configuration, the number and location of sources and acoustic receivers, and how they are deployed. Nevertheless, VSP does connote the deployment of at least some receivers in the wellbore. Most VSPs use a surface seismic source, which is commonly a vibrator on land, or an airgun, marine vibrator, watergun, or other in-sea seismic source in marine environments.
There are various VSP configurations including zero-offset VSP, offset VSP, walkaway VSP, vertical incidence VSP, salt-proximity VSP, multi-offset VSP, and drill-noise or seismic-while-drilling VSP. Checkshot surveys are similar to VSP in that acoustic receivers are placed in the borehole and a surface source is used to generate an acoustic signal. However, a VSP is a more detailed than a checkshot survey. The VSP receivers are typically more closely spaced than those in a checkshot survey; checkshot
surveys may include measurement intervals hundreds of meters apart. Further, a VSP uses the reflected energy contained in the recorded trace at each receiver position as well as the first direct path from source to receiver while the checkshot survey uses only the direct path travel time.
Microseismic events, also known as micro-earthquakes, may be produced during hydrocarbon and geothermal fluid production operations. Typically microseismic events are caused by shear-stress release on pre-existing geological structures, such as faults and fractures, due to production/injection induced perturbations to the local earth stress conditions. In some instances, microseismic events may be caused by rock failure through collapse, i.e., compaction, or through hydraulic fracturing. Such induced microseismic events may be induced or triggered by changes in the reservoir, such as depletion, flooding or stimulation, in other words the extraction or injection of fluids. The signals from microseismic events can be detected in the form of elastic waves transmitted from the event location to remote sensors. The recorded signals contain valuable information on the physical processes taking place within a reservoir.
Various microseismic monitoring techniques are known, and it is also known to use microseismic signals to monitor hydraulic fracturing and waste re-injection. The seismic signals from these microseismic events can be detected and located in space using high bandwidth borehole sensors. Microseismic activity has been successfully detected and located in rocks ranging from unconsolidated sands, to chalks to crystalline rocks.
While VSPs and microseismic surveys can provide valuable information about a formation, it is necessary to derive the orientation and location of the seismic sensors that are deployed for acquiring measurement data. Knowing the receiver depths and positions and orientation of the sensors when the tool reaches its required acquisition position is a required parameter for the processing of seismic and microseismic data. The more accurately this position is determined, the better.
Positions of the receivers can be determined by comparing and correlating the length of the cable, or sensor signals down the well with a previously determined well profile, such as depth or Gamma Ray. Sometimes however, the well profile and depth are not well known and receiver positioning errors can be introduced, causing inaccurate mapping of seismic events.
The orientation of the multi-axis sensors in seismic and microseismic data acquisition is normally determined by firing a shot or producing an event at a known surface location or set of locations or at known depths in an adjacent monitor well. Note FIG. 7. The amplitude of arrival of the event at the multi-axis sensors is compared to the known location of the event. From this the orientation of the multi-axis sensors can be determined.
There is a need, however, for improving the currently available techniques for acquiring and processing such borehole measurements. The process of determining receiver orientations requires time and effort to produce the known shot locations. The time required to perform this process would be greatly reduced or even eliminated altogether if the orientation of the sensors were known during the deployment of the multi-axis receiver array. Furthermore, as discussed above, in some circumstances it is desirable to determine or confirm the well profile as the tools are deployed in the well.
The limitations of conventional borehole seismic techniques noted in the preceding are not intended to be exhaustive but rather are among many which may reduce the effectiveness of previously known borehole seismic methods and systems. The above should be sufficient, however, to demonstrate that borehole seismic techniques existing in the past will admit to worthwhile improvement.